FIG. 1 shows one example of a conventional drilling system for drilling an earth formation. The drilling system includes a drilling rig 10 used to turn a drilling tool assembly 12 that extends downward into a well bore 14. The drilling tool assembly 12 includes a drill string 16, and a bottomhole assembly (BHA) 18, which is attached to the distal end of the drill string 16. The “distal end” of the drill string is the end furthest from the drilling rig.
The drill string 16 includes several joints of drill pipe 16a connected end to end through tool joints 16b. The drill string 16 is used to transmit drilling fluid (through its hollow core) and to transmit rotational power from the drill rig 10 to the BHA 18. In some cases the drill string 16 further includes additional components such as subs, pup joints, etc.
The BHA 18 includes at least a drill bit 20. BHA's may also include additional components attached between the drill string 16 and the drill bit 20. Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, subs, hole enlargement devices (e.g., hole openers and reamers), jars, accelerators, thrusters, downhole motors, and rotary steerable systems.
In general, drilling tool assemblies 12 may include other drilling components and accessories, such as special valves, such as kelly cocks, blowout preventers, and safety valves. The drill bit 20 in the BHA 18 may be any type of drill bit suitable for drilling earth formation. Two common types of drill bits used for drilling earth formations are fixed-cutter (or fixed-head) bits and roller cone bits. FIG. 2 shows one example of a fixed-cutter bit. FIG. 3 shows one example of a roller cone bit.
Referring to FIG. 2, fixed-cutter bits (also called drag bits) 21 have a bit body 22 having a threaded connection at one end 24 and a cutting head 26 formed at the other end. The head 26 of the fixed-cutter bit 21 includes a plurality of ribs or blades 28 arranged about the rotational axis of the drill bit and extending radially outward from the bit body 22. Cutting elements 29 are embedded in the raised ribs 28 to cut formation as the drill bit is rotated on a bottom surface of a well bore. Cutting elements 29 of fixed-cutter bits include polycrystalline diamond compacts (PDC) or specially manufactured diamond cutters. These drill bits are also referred to as PDC bits.
Referring to FIG. 3, roller cone bits 30 includes a bit body 32 having a threaded connection at one end 34 and one or more legs extending from the other end. A roller cone 36 is mounted on each leg and is able to rotate with respect to the bit body 32. On each cone 36 of the drill bit 30 are a plurality of cutting elements 38, arranged in rows about the surface of the cone 36 to contact and cut through formation encountered by the drill bit. Roller cone bits 30 are designed such that as a drill bit rotates, the cones 36 of the roller cone bit 30 roll on the bottom surface of the well bore (called the “bottomhole”) and the cutting elements 38 scrape and crush the formation beneath them. In some cases, the cutting elements 38 on the roller cone bit 30 include milled steel teeth formed on the surface of the cones 36. In other cases, the cutting elements 38 include inserts embedded in the cones. These inserts are tungsten carbide inserts or polycrystalline diamond compacts. In some cases hardfacing is applied to the surface of the cutting elements and/or cones to improve wear resistance of the cutting structure.
For a drill bit 20 to drill through formation, sufficient rotational moment and axial force must be applied to the drill bit 20 to cause the cutting elements of the drill bit 20 to cut into and/or crush formation as the drill bit is rotated. The axial force applied on the drill bit 20 is referred to as the “weight on bit” (WOB). The rotational moment applied to the drilling tool assembly 12 at the drill rig 10 (usually by a rotary table or a top drive mechanism) to turn the drilling tool assembly 12 is referred to as the “rotary torque”. The speed at which the rotary table rotates the drilling tool assembly 12, measured in revolutions per minute (RPM), is referred to as the “rotary speed”. Additionally, the portion of the weight of the drilling tool assembly supported at the rig 10 by the suspending mechanism (or hook) is typically referred to as the hook load.
During drilling, the actual WOB is not constant. Some of the fluctuation in the force applied to the drill bit may be the result of the drill bit contacting with formation having harder and softer portions that break unevenly. However, in most cases, the majority of the fluctuation in the WOB can be attributed to drilling tool assembly vibrations. Drilling tool assemblies can extend more than a mile in length while being less than a foot in diameter. As a result, these assemblies are relatively flexible along their length and may vibrate when driven rotationally by the rotary table. Drilling tool assembly vibrations may also result from vibration of the drill bit during drilling. Several modes of vibration are possible for drilling tool assemblies. In general, drilling tool assemblies may experience torsional, axial, and lateral vibrations. Although partial damping of vibration may result due to viscosity of drilling fluid, friction of the drill pipe rubbing against the wall of the well bore, energy absorbed in drilling the formation, and drilling tool assembly impacting with well bore wall, these sources of damping are typically not enough to suppress vibrations completely.
These problems may be increasingly significant when dealing with directional wells. Directional drilling involves certain terms of art, which are presented for background information. The “build rate” is the positive change in inclination over a normalized length (e.g., 3°/100 ft.). A negative change in inclination would be the “drop rate.”
A long-radius horizontal well is characterized by build rates of 2 to 6°/100 ft, which result in a radius of 3,000 to 1,000 ft, respectively. This profile is typically drilled with conventional directional-drilling tools, and lateral sections of up to 8,000 ft have been drilled.
Medium-radius horizontal wells have build rates of 6 to 35°/100 ft, radii of 1,000 to 160 ft, respectively, and lateral sections of up to 8,000 ft. These wells are drilled with specialized downhole mud motors and conventional drillstring components. Double-bend assemblies are designed to build angles at rates up to 35°/100 ft. The lateral section is often drilled with conventional steerable motor assemblies.
In practical terms, a well is classified as medium radius if the bottomhole assembly (BHA) cannot be rotated through the build section at all times. At the upper end of the medium radius, drilling the maximum build rate is limited by the bending and torsional limits of API tubulars. Smaller holes with more-flexible tubulars have a higher allowable maximum dogleg severity (DLS). Dogleg severity is a measure of the amount of change in the inclination, and/or azimuth of a borehole, usually expressed in degrees per 100 feet of course length. In the metric system, it is usually expressed in degrees per 30 meters or degrees per 10 meters of course length.
Short-radius horizontal wells have build rates of 5 to 10°/3 ft (1.5 to 3°/ft), which equates to radii of 40 to 20 ft, respectively. The length of the lateral section varies between 200 and 900 ft. Short-radius wells are drilled with specialized drilling tools and techniques. This profile is most commonly drilled as a re-entry from any existing well.
The method used to obtain the measurements needed to calculate and plot a 3D well path is called a directional survey. Three parameters are measured at multiple locations along the well path—MD, inclination, and hole direction. MD is the actual depth of the hole drilled to any point along the wellbore or to total depth, as measured from the surface location. Inclination is the angle, measured in degrees, by which the wellbore or survey-instrument axis varies from a true vertical line. An inclination of 0° would be true vertical, and an inclination of 90° would be horizontal.
Hole direction is the angle, measured in degrees, of the horizontal component of the borehole or survey-instrument axis from a known north reference. This reference is true north, magnetic north, or grid north, and is measured clockwise by convention. Hole direction is measured in degrees and is expressed in either azimuth (0 to 360°) or quadrant (NE, SE, SW, NW) form.